ML20040G970
| ML20040G970 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 01/26/1982 |
| From: | Elsasser T, Lipinski D, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20040G961 | List: |
| References | |
| 50-245-81-16, 50-336-81-15, NUDOCS 8202160678 | |
| Download: ML20040G970 (14) | |
See also: IR 05000245/1981016
Text
,
d
.
U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT
'9
"
50-245/81-16
Report No. 50-336/81-15
50-245
Docket No. 50-336
C
License No.DPR-65
Priority
Category
---
Licensee: Northeast Nuclear Energy Company
P.O. Box 270
Hartford, Connecticut 06101
Facility Name:
Millstone Nuclear Power Station, Units 1 & 2
Inspection at:
Waterford, Connecticut 06385
Inspection conducted: November 1, 1981 thru January 2, 1982
Inspectors:
e7f
//f/fp
[
Shedlosky,
Resident Inspector
'date signed
2-a-42
D. R. Lipiriski, Resident Inspector
date signed
date signed
Approved by:
N d ,j ,,f,
h
g,g
7. C. Elsatter, Chief
.
date signed
Reactor Projects Section 1B,
Division of Resident & Project Inspection
Inspection Summary:
Inspection on November 1,1981 thru January 2,1982 (Combined Report Nos. 50-245/81-16
and50-336/81-15.)
Areas Inspected: Routine, onsite, regular and backshift inspection by two resident
inspectors (170 hours0.00197 days <br />0.0472 hours <br />2.810847e-4 weeks <br />6.4685e-5 months <br />, Unit 1; 166 hours0.00192 days <br />0.0461 hours <br />2.744709e-4 weeks <br />6.3163e-5 months <br />, Unit 2). Areas inspected included the
control rooms and the accessible portions of the Unit I reactor, turbine, radioactive
waste, gas turbine generator, and intake buildings; the Unit 2 primary containment,
enclosure, auxiliary, turbine and intake buildings; the condensate polishing facility;
radiation protection; physical security; fire protection; plant operating records;
modifications; a plant trip, surveillance testing; calibration; maintenance; core power
distribution limits; and reporting to the NRC.
Results: Of the fourteen areas inspected, two items of noncompliance were identified:
(failure to have the required number of instrument channels in service for turbine
control valve fast closure RPS trip, and failure to follow written procedures, paragraph
4.)
Region I Form 12
(Rev. April 77)
820216067B 820128
~
PDR ADOCK 05000245
0,
,
_
.-
- -
.
-
-_ . . . .
-
. . - . -
.
.
.--
.
.
,
DCS IDENTIFICATION NOS.
NRC INSPECT 12N NO. 50-245/80-16
50-336/80-15
No.
Report Paragraph
50245-810925
10
50245-811006
10
50245-811013
10
50245-811110
10
50245-811112
10
50245-811214
10
'
50245-811117
10 & 4
50336-810825
10
50336-810925
10
.
50336-810928
10
50336-811008
10
50336-811026
10
'
50336-811109
10
50336-811111
10
50336-811203
10
50336-811008
10
,
_
I
s
,-c-
--t,
, ---
9
w
y
<ve,
,
_ _ _ _ _ _ _ _ - _ _
_ _ _
_
_ _ _ _ _
- _ _ _
_
- _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
.
DETAILS.
1.
Persons Contacted
The below listed technical and supervisory level personnel were among
those contacted:
A. Cheatham, Radiological Services Supervisor
J. Crockett, Unit 3 Superintendent
F. Dacimo. Quality Services Supervisor
E. C. Farrell, Station Services Superintendent
B. Granados, Health Physics Supervisor
H. Haynes, Unit 2 Instrumentation and Control Supervisor
'R. J. Herbert, Unit 1 Superintendent
J. Kangley, Chemistry Supervisor
J. Keenan, Unit 2 Engineering Supervisor
J. J. Kelley, Unit 2 Superintendent
E. J. Mroczka, Station Superintendent
V. Papadopoli, Quality Assurance Supervisor
R. Place, Unit 2 Engineering Supervisor
R. Palmieri, Unit.1 Engineering Supervisor
W. Romberg Unit 1 Operations Supervisor
S. Scace, Unit 2 Operations Supervisor
F. Teeple, Unit 1 Instrumentation and Control Supervisor
W. Varney, Unit 1 Maintenance Supervisor
P. Weekley, Security Supervisor
2.
Status of Unresolved and Open Items
New items:
Unit 1
245/81-16-01' Training for plant control room operators in process computer
inputs, operations, and interpretation of outputs. (Paragraph 5)
245/81-16-02 Evaluate the installation of annunciatQrs or alarms to indi-
cate when process computer calculated core thermal limits are exceeded.
(Paragraph 5)
3.
Review of Plant Operation - Plant Inspections (Units 1 and 2)
The inspector reviewed plant operations through direct inspection and
observation of Units 1 and 2 throughout the reporting period. Unit 1 operated
at power through the inspection period mh exception of a reactor trip on
December 28, 1981. Unit 2 operated at full ' power until December 5,1981, when
a refueling and maintenance outage was commenced. Currently, it is estimated
-
that the outage will be completed and the unit brought on line during March 1982.
3
.
a.
Instrumentation
Control room process instruments were observed for correlation between
channels and for conformance with Technical Specification requirements.
No unacceptable conditions were identified.
b.
Annunciator Alanns
The inspector observed various alarm conditions which had been received
and acknowledged. These conditions were discussed with shift personnel
who were knowledgeable of the alarms and actions required. During plant
inspections, the inspector observed the condition of equipment associated
with various alanrs. No unacceptable conditions were identified,
c.
Shift Manning
The operating shifts were observed to be staffed to meet the operating
requirements of Technical Specifications, Section 6, both to the
number and type of licenses. Control room and shift manning was observed
to be in conformance with Technical Specifications and site administrative
procedures.
d.
Radiation Protection Controls
Radiation protection control areas were inspected. Radiation Work Permits
in use were reviewed, and compliance with those documents 3 as to protective
clothing and required monitoring instruments, was inspected.
Proper
posting of radiation and high radiation areas was reviewed in addition to
verifying requirements for wearing of appropriate personal monitoring
devices. There were no unacceptable conditions identified.
e.
Plant Housekeeping Controls
Storage of material and components was observed with respect to
prevention of fire and safety hazards.
Plant housekeeping was evaluated
with respect to controlling the spread of surface and airborne con-
tamination. There were no unacceptable conditions identified.
'
f.
Fire Protection / Prevention
The inspector examined the condition of selected pieces of fire fighting
equipment. Combustible materials were being controlled and were not found
near vital areas.
Selected cable penetrations were examined and fire
barriers were found intact. Cable trays were clear of debris. No un-
acceptable conditions were identified.
g.
Control of Equipment
During plant inspections, selected equipment under safety tag control was
examined.
Equipment conditions were consistent with information in plant
control logs.
4
.
.
.
h.
Instrument Channels
Instrument channel checks recorded on routine logs were reviewed.
An independent comparison was made of selected instruments. No
unacceptable conditions were identified.
i. Equipment Lineups
The inspector examined breaker positions on switchgear and motor control
centers in accessible portions of the plant. Equipment conditions, in-
cluding valve lineups, were reviewed for conformance with Technical Speciff-
cations and operating requirements. No unacceptable conditions were . identified.
4.
Loss of Control of Valve Position for Safety Related Instrumentation (Unit 1)
At 1850 on November 17, 1981, while operating at full power, Millstone Unit 1
experienced an apparently spurious trip of the "B" Reactor Protective System
(RPS). Alams associated with "B" RPS indicated that a main turbine load
rejection had been sensed.
Other plant parameters, alams, and breaker and
valve position indications indicated that no load rejection had actually
occurred.
Further investigation found turbine control valve fast closure pressure switch
PS-39 isolated. This pressure switch is cae of four which provide inputs of
control valve oil pressure to the main turbine load reject logic.
Pressure
switch PS-39 was returned to service at 2020.
Surveillance had been conducted
on these pressure switches earlier on November 17 using Surveillance Procedure
SP408G, revision 2, " Turbine Control Valve Fast Closure Functional Test /Cali-
bration" and was completed at 0850. This procedure requires shutting the isola-
tion valve to PS-39 and, later, requires reopening the 31ve.
In its restoration
section, SP408G requires a further check of isolation valve position. Depart-
mental Instruction 1-I&C-9.03, " Instrumentation Line-up Restoration", requires
that such verifications be conducted independently by a technician different from
the valve manipulator. This is an item of noncompliance (245/81-16-03).
The isolation of pressure switch PS-39 reduced the number of operable fast
closure sensor channels below that required by Technical Specifications.
This is an item of noncompliance (245/81-16-04).
The licensee has conducted training for instrumentation and control technicians
to reinforce the need for proper valve control.
The licensee has implemented
a program to label heretofore unlabeled valves on instrument racks containing
safety-related instrumentation and to color code valve hand operators to
further differentiate nomally open and nomally shut valves on these racks.
The inspector has no further questions regarding these corrective actions.
5
.
.
-
.
-5.
Core Power Distribution Limits - Unit 1
a.
Scope
The inspector observed conduct of the "Whole Core LPRM Calibration and
BASE Distribution" with process computer program 00-1. A sample of
" Periodic Core Evaluation," program P-1, edits were reviewed. . Licensee
plans for ascertaining operation of the core within themal limits during
periods of process computer non-availability and for recovery from process
computer outages were also reviewed. The inspector also assessed the
implementation of a revised process computer program package, GEXL+15.
b.
Documents Reviewed
General Electric GEXL+15 Program Specifications for programs P1 and 00-1.
---
General Electric Data Base Class .1 thru 3 (257HA231 BH Rev.1).
---
Process Computer Operating . Instructions, Vol.1 GEK 27782C May 81.
---
General Electric Field Disposition Instruction Appendix A. "NSS
---
Demonstration and Test for Plus 15."
Various process computer edits (sample).
---
"4020 Computer Software Changes", 1-ENG-10.02, Revision 2.
---
c.
Findings
0D-1 operation. All Traversing Incore Probe (TIP) data was properly
---
obtained and accepted by the pmcess computer.
P-1 operation. The implementa ion of GEXL+15 has expanded the voltne
---
and utility of the P-1 data p. rentation. For example, this edit
presents Maximum Fraction of Limiting Power Density (MFLPD), Maximum
Fraction of Critical Power Ratio (MFLCPR), and Ratio of Average Planar
Linear Heat Generation Rate to its limiting' value (MAPRAT) as well as
the locations of the twelve fuel bundles most closely approaching
thermal limits. Also presented is a fraction of rated core thermal
power in a format readily commrable to MFLPD for use during power
t
maneuvers.
--- Process Computer Non-Availability. The licensee utilizes the Back-up
Core Limits Evaluation (BUCLE) off-line, remote computer facility of
General Electric Company. The implement of GEXL+15 provides enhanced
communication of recorded data from the magnetically recorded " Security
Log" to the BUCLE computer to simplify BUCLE use. The accessibility
and close correspondence of the results of BUCLE and on-line process
computer was demonstrated. The licensee does not anticipate critical
plant operations under conditions requiring manual calculation of
limits by the TBAR method.
Thermal Limits. The sample of process computer edits examined
---
indicated that the plant was operated within the bounds of applicable
thermal limits.
On two occasions on December 7, initial results of
the P-1 calculations indicated that themal limits had been exceeded.
On each of these occasions, however, the process computer determination
of control rod pattern erroneously indicated an asymetric condition.
._
___ ___ __ ___
6
.
.
'
.
This resulted in the calculation of inaccurate flux levels for
unmonitored core locations and, thus, inaccurate thermal parameters.
In both cases, operators determination of symetry pattern and manual
input of symmetry code was successful in obtaining a calculation
using actual symmetry, which was within thennal limits. The inspector
reviewed other. indications of plant status. These parameters, together
with the bracketing P-1 data, indicate that thermal limits were not
actually. exceeded during the times of improper calculations.
A failed circuit card was found in the process computer digital input
section involving rod position scanning. The card has been replaced.
Implementation of Changes and Alterations. The implementation of
---
the GEXL+15 program has been a major task for the station nuclear
engineers. This has involved witnessing of demonstration tests and
program check-out, review of documents, comparison of results of
GEXL+ and GEXL+15 computations, and interface verification with BUCLE.
Training for plant operator: wa: deemed incufficient, however, operator
unfamiliarity with the process computer edits contributed to the
confusion regarding the proximity to core thermal limits. For example,
the inspector pointed out the apparent discrepancy in Average Planar
Linear Heat Generation Rate at about 2030 on December 7.
The compu-
tation time of the P-1 edit indicating the limit was being exceeded
was 1800 on December 7.
A " flag" variable indicating the process
computer interpretation of control rod symmetry signalled the difficulty
during the P-1 computed at 1500 on December 7.
The licensee has committed to complete retraining of operators in
process computer inputs, outputs, and operations by March 31, 1982. The
licensee has also committed to review the
value
of annunciating
or otherwise alarming the result of any determination of a thermal
limit being exceeded.
These are identified as open items.
(245/81-16-01 and 245/81-16-02)
6.
Unit 1 Trip of December 28, 1981
At 0010 on December 28, 1981, Millstone Unit 1 sustained a reactor trip due
to low reactor vessel water level. The plant had been operating at full
power and efforts were being made to reduce condenser sea water intrusion by
applying sawdust and varying circulating water flow. Varying circulating
water system lineup and flow is an evolution which is known to produce a
rippling or wave action in the hotwell
at Unit 1.
At 0010, main condensate
pumps, condensate booster pumps, and main feed pumps tripped on low suction
pressure. Reactor vessel level rapidly dropped initiating the reactor scram.
Main Steam Isolation Valves (MSIV's) were manually shut to terminate coolant
inventory loss. The lowest reactor vessel water level reached was an indicated
level of -35 inches (91 inches above the top of the active fuel). The condenser
hotwell level recovered rapidly and the normal feedwater path was returned to
service. MSIV's were reopened and the normal cool-down pathway to the main
condenser was restored.
-
'
7
-
.
Further investigation revealed difficulties in the condenser hotwell level
measurement and control system. Two hotwell level measurement loops are
provided; one at a time may be selected as the controlling loop. Each
hotwell level measurement loop includes an electro-mechanical level sensor
(Masoneillan 12500 series). As water level changes, the bouyancy, and thus
the weight, of a displacer body varies. This variation in weight of the displacer
is mechanically transmitted to an inductive-coupling electrical pick up. The
"A" loop had been selected for control at the time of the trip. An attempt
to calibrate the level sensor revealed that it had previously indicated
a level 17" above the actual hotwell level. Troubleshooting disclosed that
several components of the mechanical linkage were loose. The linkage was
tightened and "A" level sensor was calibrated satisfactorily.
"A" level sensor
was installed in 1969. The looseness found in mechanical linkages is deemed
by the licensee to be due to normal wear. This level sensor will be replaced
when replacement materials become available. The "B" level sensor was installed
in February 1981 and was found to be in calibration. The "B" loop is presently
selected for indication and control with "A" available as a backup.
Prior to the trip, the plant had been operated with an intermittent hotwell
level alarm. High hotwell level and low hotwell level were annunciated by a
common alarm and displayed through a common window.
It had been assumed that
the alarm was a high-level alam.
In retrospect, it was a low-level alarm.
The licensee has separated the alams so that the low-level alarm and high-
level alarm are displayed in separate windows.
The unit was made critical at 0426 on December 29, 1981. No unacceptable
conditions were noted.
7.
Review of Plant Operations - Logs and Records - (Units 1 and 2)
During the inspection period, the inspector reviewed operating logs and
records covering the inspection time period against Technical Specifications
and Administrative Procedure Requirements.
Included in the review were:
.
'
daily during control room
Shift Supervisor's Log
-
surveillance
Plant Incident Reports
- 11/1/81 through 1/2/82
all active entries
Jumper and Lifted Leads Log
-
Maintenance Requests and Job Orders
- all active entries
ai' active entries
Construction Work Permits
-
Safety Tag Log
- all active entries
Plant Recorder Traces
- daily during control room
surveillance
Plant Process Computer Printed
- daily during control room
Output
surveillance
daily during control room
Night Orders
-
surveillance
.
.
_ _ _ _ _ _ _ _
8
.
.
.
The logs and records were reviewed to verify that: entries are properly
made; entries involving abnormal. conditions provide sufficient detail to
communicate equipment status, deficiencies, corrective action restoration and
testing; reccrds are being reviewed by management; operating orders do not
conflict with the Technical Specifications; logs and incident reports detail
no violations of Technical Specification or reporting requirements; and logs
and records are maintained in accordance with Technical Specification and
Adninistrative Control Procedure requirements.
There were no unacceptable conditions identified.
8.
Review of Periodic and Special Reports
Upon receipt, periodic and special reports submitted by the licensee
pursuant to Technical Specification 6.9.1 and 6.9.2 and Environmental
Technical Specification 5.6.1 were reviewed by the inspector. This review
included the following considerations:
the report includes the infnrmation
required to be reported by NRC requirements; test results and/or supporting
information are consistent with design predictions and perfonnance spec.ifica-
tions; planned corrective action is adequate for resolution of identified
problems; determination whether any information in the report should be
classified as an abnormal occurrence; and the validity of reported information.
Within the scope of the above, the following periodic reports were reviewed by
the inspector:
Monthly Operating Report Unit 1 and 2, October 1981
---
Monthly Operating Report Unit 1 and 2, November 1981
---
There were no unacceptable conditions identified.
9.
Preparation for Refueling - Unit 2
a.
Scope
A review was conducted of plans and preparations for the Unit 2 refueling
outage. Procedures for fuel handling, transfers, core verification,
inspection of fuel to be reused, and for handling and inspection of
core internals were evaluated against the requirements of ANS N18.7-1972.
Policies for the conduct of refueling concerning communications, control
of plant and refueling operations, shift manning, and shift turnover were
discussed with senior plant personnel.
b.
Documents Reviewed
1.
Plant Procedures
OP2209A
Refueling Operation
Revision 6 6-12-81
OP2209C
Preparation for and Restoration
from Core Alterations
Revision 0 8-15-80
OP2211A
Spent Fuel Inspection
Revision 2 1-8-79
OP2520
Fuel Handling Accident
Inside Containment
Revision 2 4-1-81
'
l
,
- 9
.
.
'
1
.
w
Documents Reviewed (cont'd.)
OP2501'
Incident Assessment and
Classification - Unit 2
Revision 1 9-24-81
OP2303
Fuel Handling System
Revision 10 7-16-81
MP2704A
Preparation for Reactor Vessel
Head Removal
Revision 4 7-16-81
MP2704B
Installation of Refueling Pool Seal Revision 2 1-16-81
MP2704C
Reactor Vessel Head Removal
Revision 5 6-25-79
MP2704D
Uncoupling of C.E.A. Extension
Shaft
Revision 1 11-30-77
MP2704E
Removal of In-Core -Instrumentation
Assembly
Revision 3 8-16-80
MP2704F
Removal of Upper Guide Structure
Revision 5 8-16-80
MP2704G
Removal of Core Support Barrel
Revision 2 .1-16-80
MP2704H
Installation of Core Support Barrel
Revision 1 11-20-81
MP2704I
Installation of Upper Guide
Structure
Revision 3 1-30-81
MP2704K
Coupling of C.E.A. Extension Shafts Revision 2 5-14-79
MP2704L
Reactor Vessel Head Installation
Revision 5 8-22-80
MP2704R
Removal and Installation of
Enclosure Building Equipment Hatch Revision 2 4-9-81
SNM Inventory and Control
Revision 2 4-9-81
Refueling Worklist Administrative
Control
Revision 0 2-28-80
2.
Standards
ANS N18.7-1972 " Administrative' Control for. Nuclear Power Plants"
Section 5 " Facility Administrative. Policies and Procedures."
c.
Findings
Procedure preparations for the cycle 5 refueling were completed in a
timely manner. Prerequisites were found to address the status and testing
of plant systems required for refueling, inspection of replacement fuel
and internals, conditions for spent fuel movement, status of fuel handling
equipment interlocks, and the designation and control of proper tools.
Procedures governing planned evolutions were found to address the reactivity
' status of the core; minimum operable instrumentation; step-wise instructions
for the sequence, orientation, and seating of fuel and components,
criteria for halting refueling operations; and containment status. Also
addressed were responsibilities and duties of personnel, communications.
Special Nuclear Material (SNM) accountability, shift turnover, rules for.
intervals when refueling is interrupted, and core verification. Plans for
the eventuality of fuel damage during refueling were in place. No
unacceptable conditions were identified.
_- _
- - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
m
a
10 -
- '
,
.
,
T1
10. Licensee = Event' Reports'(LER's)
The inspector reviewed the following LER's to verify that the. details
of the event were clearly reported,. including the accuracy of the
description of cause'and adequacy of corrective action. The inspector
determined whether further information was required, and whether generic
implications were involved. The inspector. also verified that the reporting
requirements of Technical Specifications and Station Administrative and
Operating Procedures had been met, that appropriate corrective action _had
been taken, that the-event was reviewed.by the Plant Operations Review-
Committee, and that the' continued operation of the facility was conducted
within the Technical Specification limits.
Unit 1
81-32 Failure of diesel driven fire pump to start during surveillance
tes ti ng.~
Test was completed satisfactorily after controller
was ' cleaned.
81-33 Setpoint drift. cue of four ECCS reactor vessel Low-Low -level
switches.
81-34 Setpoint drift.
One of four R.P.S. turbine control valve fast closure
time delay relays. This report is similar to event 81-30, however,
different relays are involved. All three are Agastat Model-
2122-A-H2SB.
81-35 Failure of one of four main steam line radiation monitors due to
loss of signal.
It is believed that the detector cable were
disturbed by construction activities in the area,
81-36 Setpoint drift.
One of'four R.P.S. drywell pressure switches.
81-37 Setpoint drift.. Two of two torus water level transmitters
indicated 1/2 inch low.
Both transmitters were recalibrated and
tested satisfactorily.
81-38 Inadvertent isolation of one of four turbine control valve fast
closure pressure switches following surveillance. See detail 6.
Unit 2
81-31 Failure of Emergency Diesel Gesra. ir 120 to start during
surveillance testing. A T c ; aio .rical connector in the
governor control was fount m d c ,
+r.e d . The test was then
completed satisfactorily.
81-32 One of two Reactor Building Closed Cooling Water headers
adninistratively declared inoperable to permit anchor bolt and
sei'smic restraint upgrading.
11
-
-
-
,
Unit 2 (cont'd.)-
81-33 Unidentified leakage from the reactor coolant system was calculated
to be in excess of one gallon per minute. Valve 2-RC-403, the
blocking valve to power operated relief valve 2-RC-402, was
found to be the source of the leakage.
It was isolated and will
undergo repair during the current refueling outage.
81-34 Instrument setting for one of four excore detectors was found to be
improper during surveillance.
81-35 Failure to conduct routine monthly surveillance on Pressurizer
Water Level and on Auxiliary Feedwater flow instruments during
August and September due to management oversight.
81-36 Replacement of 20 mechanical snubbers manufactured by Inter-
national Nuclear Safeguards with snubbers manufactured by Pacific
Scienti fic. Replacement was conducted in response to NRC Bulletin 81-01.
81-37 Failure of the Control Element Assembly (CEA) pulse counting
position indicating system due to faulted resistor in its power
supply.
81-38 Inoperable CEA. Condition existed for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> when, during trouble-
shooting, the CEA began to respond normally. No cause of this
failure has been identified.
81-39 Failure of reactor cold leg temperature inputs to RPS system "B"
due to steam condensation in an open terminal box.
11. Plant Maintenance and Modifications
During the inspection period, the inspector frequently observed various
maintenance and problem investigation activities. The inspector reviewed
these activities to verify:
compliance' with regulatory requirements,
including those stated in the Technical Specifications; compliance with
the administrative and maintenance procedures; compliance with applicable
codes and standards; required QA/QC involvement; proper use of safety
tags; proper equipment alignment and use of jumpers; personnel qualifica-
tions; radiological controls for worker protection; fire protection;
retest requirements; and ascertain reportability as required by Technical
Specifications.
In a similar manner the implementation of design changes
and modifications were reviewed.
In addition to those items addressed
above, the licensee's safety evaluation was reviewed. Compliance with
requirements to update procedures and drawings were verified and post
modification acceptance testing was evaluated.
The following activities
were included in this review:
>
12
.
Unit 1
Decommissioning and decontamination of the Unit 1 solid radio-
---
active waste drum handling system and storage area.
Installation of containment post-accident hydrogen sampling system.
---
Repairs to operator of valve 1-CU-3, a containment isolation valve
---
in the Reactor Water Clean-Up System.
Unit 2
Troubleshooting and calibratior, of #1 Safety Injection Tank level
---
transmitter (Foxboro type 823DP).
Overhaul of "A" Diesel Generator.
---
Low Pressure Turbine inspection.
---
Steam Generator nozzle dam installation.
---
Feedwater Heater Inspection.
---
12.
Inspector Witnessing of Surveillance' Tests
The inspector witnessed the performance of surveillance testing of
selected components to verify that; the surveillance test procedure was
properly approved and in use; test instrumentation required by the procedure
was calibrated and in use; technical specifications were satisfied prior to
removal of the system from service; the test was performed by qualified
personnel; the procedure was adequately detailed to assure performance of
a satisfactory surveillance; and, test results satisfied the procedural
acceptance criteria, or were properly dispositioned. The inspector
witnessed the perfonnance of:
Unit 1
--- MSIV Closure Functional Test per SP408E, Revision 1, on November 16.
Unit 2
Safety Injection Tank Analysis for Boron per SP2836, Revision 1,
---
on November 10.
Boron Analysis per CP808G, Revision 0,on November 10.
---
--- Chloride Analysis (Mercuric Nitrate Titration) per CP808M, Revision 0,
on November 10.
Turbine Driven Auxiliary Feedwater System Operability Test per
---
SP26108, Revision 4,CH-2,on November 20.
Terry Turbine Auxiliary Feedwater Pump Operational Readiness Test
---
per EN2110/-1, Revision 2,CH-1,on November 20.
Ammonia Colorimetric Detennination per CP2808D, Revision 0,on December 1.
---
Low Silica Spectrophotometric Method per CP2808S, Revision 0,on December 1.
---
Secondary Coolant Analysis for Total Activity per CP2833, Revision 2,
---
on December 1.
Calculating Primary to Secondary Leak Rate per CP2806Y, Revision 1,
---
on December 1.
,.
.
13
~
.
Unit 2 (cont'd.)
Reactor Coolant Gross Activity per SP2831, Revision 0,on December 3.
---
Gama Counting Determination (degassed) per CP806/2806L, Revision 1,
---
on December 3.
Factor Coolant Analysis for Dissolved Oxygen, Fluoride,- and
---
Chloride per SP2830, Revision 1,on December 3.
Orion pH Meter per CP2801K, Revision 1,on December 3.
---
Conductivity Bridge (Leeds & Northrup) per CP801/2801J, Revision 1,
---
on December 3.
0xygen (Dissolved) Comparator per CP808/2808, App. AH, Revision 6,
---
on December 3.
13. _ Review of Radioactive Material Shipments - (Unit 1)
The inspector reviewed the activities concerning the shipment of radio-
active waste to the Barnwell, S.C., burial site. Those activities
included receipt inspections of the shipping cask and liner, solidification
of material, radiation surveys and the completion of administrative and
quality control requirements prior.to shipment. These inspections
concerned:
Dewatered Purification Media
November 18, 1981
---
L.S.A. Boxes and Drums
November 20, 1981
---
14. Bomb' Threat-(Unitsel and 2)
At 2014 on December 28, 1981, a bomb threat was received by the Stone
and Webster Security Force involved in the construction of Millstone
Unit 3.
The caller indicatea that all three units were affected and
identified the time of detonation.
Further calls were received at
2023 and 2028. The licensee executed appropriate segments of the
emergency plan. No bomb was found. The time for the threatened de-
tonation passed without event. The caller has not been identified,
15. Exit Interview
At periodic intervals during the course of the inspection, meetings
were held with senior facility management to discuss the inspection
scope and findings.